Note: Descriptions are shown in the official language in which they were submitted.
CA 02655348 2009-02-24
Title: METHODS FOR ALLOWING MULTIPLE FRACTURES TO
BE FORMED IN A SUBTERRANEAN FORMATION FROM AN OPEN HOLE
WELL
FIELD OF THE INVENTION
The present invention relates generally to fracturing an open hole
completed well or well section. In some embodiments, the present invention
relates to
methods for allowing multiple fractures to be formed in a subterranean
formation from a
non-vertical open hole well section.
BACKGROUND OF THE INVENTION
In fracturing subterranean formations from typical underground cased
wells, the point of initiation of the fractures in the well may be relatively
precisely
located because the fracture can only initiate at the location where the
casing has been
perforated. However, it is sometimes necessary or desirable to fracture a
subterranean
formation from a non-cased, or open hole, completed well section. In those
scenarios,
one particular challenge is to be able to initiate the fracture at a desired
location in the
well.
In open hole scenarios, the fracture may occur at an unpredictable location
in the well bore, such as may be due to the effects in the open hole caused by
applied
fluid pressure in the well. For example, when there is no casing or other
fluidly
impermeable barrier between pressurized well fluid and the exposed rock that
forms the
wall of the open hole, the rock could crack and fracture at an undesirable or
intermediate
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CA 02655348 2009-02-24
location. The inability to control or pinpoint the fracture initiation
location in open hole
wells may be particularly important, for example, when attempting to form
multiple
fractures in a subterranean formation from a non-vertical section of an open
hole well.
As used herein, a "non-vertical" well may be a horizontal, lateral, inclined,
deviated,
directional or similar well.
Various techniques have been proposed for isolating the fracture initiation
location in an uncemented lined well. For example, one current system utilizes
one or
more packer and sliding sleeve for segmenting a selected leg of a well bore.
Using
mechanical isolation, this equipment allows intervals of a horizontal well
section to be
segregated and stimulated separately. However, few techniques are believed to
exist for
open hole wells. One system utilizing a hydrojetting tool for jetting fluid
through a
nozzle at high pressures has been proposed for fracturing the formation where
the fluid
jet impacts the borehole wall. Positioning the jetting tool at the desired
location allegedly
results in the initiation of a fracture at that location.
Presently known techniques for isolating the fracture initiation location in
an uncemented lined well may involve the use of specialized equipment that may
be large
and complex, costly to manufacture and utilize, and/or subject to sticking in
the well and
failure. While open hole completions typically require non-costly or complex
equipment
to be installed in the producing section of the well, the effectiveness and/or
efficiency of
proposed open hole fracturing techniques is questionable. For example, when
the
aforementioned hydrojetting tool is used to create a fracture, pressure must
be maintained
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CA 02655348 2009-02-24
in the well bore annulus. Any weakness in the rock along the bore hole wall
may result
in the formation of an unexpected or undesirable fracture.
It should be understood, however, that the above-described examples,
features and/or disadvantages are provided for illustrative purposes only and
are not
intended to limit the scope or subject matter of the claims of this patent or
any patent or
patent application claiming priority hereto. Thus, none of the appended claims
or claims
of any related patent or patent application should be limited by the above
discussion or
construed to address, include or exclude the cited examples, features and/or
disadvantages, except and only to the extent as may be expressly stated in a
particular
claim. Further, the above exemplary disadvantages should be evaluated on a
case-by-
case basis.
Accordingly, there exists a need for methods useful for allowing the
formation of fractures in a subterranean formation from an open hole portion
of a well
bore having one or more of the following attributes, capabilities or features:
allows the
formation of multiple fractures from a non-vertical open hole well portion;
allows the
formation of multiple distinct fractures from a non-vertical open hole well
portion; allows
the formation of multiple fractures from a horizontal open hole well portion;
allows
relatively precise location of fractures in an open hole well portion;
utilizes an easily
removable coating that is substantially impermeable, strong and/or coherent,
essentially
eliminates the effects of poroelasticity upon the formation under the coating
regardless of
the nature or type of hydrocarbons produced therefrom and in a wide range of
temperatures, may be 100% soluble, or any combination thereof; protects each
fracture
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CA 02655348 2009-02-24
from damage caused by subsequent formation fracturing; includes a non-damaging
plug
placed across the fracture and along a portion of the well bore proximate
thereto to isolate
the fracture from any subsequent fracturing operations; includes a proppant
plug that does
not substantially invade the fracture, does not impair conductivity of the
fracture, is easy
to clean out, or a combination thereof; may be implemented with the use of
coiled tubing
or a jointed pipe string; does not require additional, complex or costly
equipment; is
effective, cost efficient, reliable and/or easy to implement.
BRIEF SUMMARY OF THE INVENTION
In some embodiments, the present invention involves a method of
allowing at least two fractures to be formed in a subterranean formation from
a non-
vertical, open hole section of an underground well bore. A removable coating
is provided
across substantially the entire surface of the wall of the well bore in the
section of the
well bore from which the fractures will be initiated. The coating is
selectively removed
at a desired first fracture initiation location in the well bore sufficient to
allow a first
fracture to be formed in the subterranean formation therefrom and without
substantially
removing the coating from the remainder of the section of the well bore from
which the
fractures will be initiated. The first fracture is allowed to be formed in the
subterranean
formation in the vicinity of the desired first fracture initiation location. A
first plug is
placed in the well bore around the first fracture initiation location after
the first fracture is
formed. The first plug shields the subterranean formation from fracturing at
the first
fracture location during subsequent fracturing from the open hole section and
does not
impair conductivity of the first fracture.
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In many embodiments, the present invention involves a method of
reducing the effects of linear poroelasticity on the subterranean formation
forming the
wall of an open hole well bore section sufficient to prevent the fracturing
thereof during
the fracturing of the subterranean formation from one or more adjacent
locations in the
open hole well bore. These embodiments includes providing a substantially
thin,
impermeable, strong and coherent coating across sub coating across
substantially the
entire surface of the wall of the open hole well bore. The coating is
selectively removed
from the open hole well bore wall at a desired first fracture initiation
location in the open
hole well bore without removing the coating from the remainder of the open
hole well
bore. A first fracture is allowed to be formed in the subterranean formation
in the vicinity
of the desired first fracture initiation location, while the remainder of the
open hole well
bore is shielded from fracturing by the coating.
In some embodiments, the present invention involves a method of
initiating a fracture in a subterranean formation from a non-vertical open
hole well bore
section at a desired location for the production of hydrocarbons therefrom
regardless of
the type of hydrocarbons. These embodiments include providing an acid-soluble
cement
dispersion into the well bore section through a tubing that is disposed in the
well bore.
The acid-soluble cement dispersion is allowed to form a substantially
impermeable,
easily removable and entirely soluble coating across substantially the entire
surface of the
wall of the well bore section. A coating remover is provided through the
tubing to a
desired first fracture initiation location in the well bore section proximate
to the end of
the tubing to remove the coating at that location without removing the coating
from any
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CA 02655348 2009-02-24
other portion of the wall of the well bore section. The subterranean formation
is allowed
to be fractured in the vicinity of the first fracture initiation location. The
fracture is
isolated to prevent damage to the fracture during subsequent formation
fracturing from
the well bore section.
There are embodiments of the present invention involving a method of
allowing multiple distinct fractures to be formed in a subterranean formation
from a non-
vertical open hole section of a well bore. These embodiments include inserting
a tubing
into the well bore and providing a coating-forming solution through the tubing
into the
well bore. The coating-forming solution is allowed to at least substantially
fill the
section of the well bore from which the fractures will be initiated. The
coating-forming
solution is allowed to form a substantially impermeable coating on the wall of
the well
bore throughout the section of the well bore from which the fractures will be
initiated.
A coating remover is provided through the tubing to a desired first
fracture initiation location in the well bore to remove the coating at that
location
sufficient to allow a first fracture to be formed in the subterranean
formation therefrom.
The subterranean formation is fractured in the vicinity of the first fracture
initiation
location. A non-damaging proppant plug is placed across the first fracture
initiation
location and along a portion of the well bore adjacent thereto to isolate the
first fracture
from any subsequent fracturing operations. The tubing is moved to a desired
second
fracture initiation location. A coating remover is provided through the tubing
to the
second fracture initiation location in the well bore to remove the coating at
that location
sufficient to allow a second fracture to be formed in the subterranean
formation
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CA 02655348 2009-02-24
therefrom. The subterranean formation is fractured in the vicinity of the
second fracture
initiation location.
Accordingly, the present invention includes features and advantages which
are believed to enable it to advance open hole well completion technology.
Characteristics and advantages of the present invention described above and
additional
features and benefits will be readily apparent to those skilled in the art
upon consideration
of the following detailed description of preferred embodiments and referring
to the
accompanying drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
The following figures are part of the present specification, included to
demonstrate certain aspects of preferred embodiments of the invention and
referenced in
the detailed description herein:
Figure 1 is a schematic diagram of an example underground well having a
non-vertical section wherein a coating will be provided in accordance with an
embodiment of the present invention;
Figure 2 illustrates an exemplary coating provided in a non-vertical
section of the well of Figure 1 in accordance with an embodiment of the
present
invention;
Figure 3 illustrates the removal, at a first fracture initiation location, of
part of an exemplary coating provided in a non-vertical section of the well of
Figure 1 in
accordance with an embodiment of the present invention;
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CA 02655348 2009-02-24
Figure 4 illustrates the initiation of a fracture at a first fracture
initiation
location in a non-vertical section of the well of Figure 1 in accordance with
an
embodiment of the present invention;
Figure 5 illustrates the placement of an example proppant isolation plug
across the first fracture and removal, at a second fracture initiation
location, of part of an
exemplary coating provided in a non-vertical section of the well of Figure 1
in
accordance with an embodiment of the present invention;
Figure 6 illustrates the exemplary well of Figure 1 having multiple
fractures initiated from a non-vertical section thereof in accordance with an
embodiment
of the present invention; and
Figure 7 illustrates the initiation of a fracture at a second fracture
initiation
location in a non-vertical section of the well of Figure 1 in accordance with
an
embodiment of the present invention.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
Characteristics and advantages of the present invention and additional
features and benefits will be readily apparent to those skilled in the art
upon consideration
of the following detailed description of preferred embodiments of the claimed
invention
and referring to the accompanying figures. It should be understood that the
description
herein and appended drawings, being of preferred embodiments, are not intended
to limit
the appended claims or the claims of any patent or patent application claiming
priority to
this application. On the contrary, the intention is to cover all
modifications, equivalents
and alternatives falling within the spirit and scope of the claims. Many
changes may be
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CA 02655348 2009-02-24
made to the particular embodiments and details disclosed herein without
departing from
such spirit and scope.
In showing and describing the preferred embodiments, like or identical
reference numerals are used to identify common or similar elements. The
figures are not
necessarily to scale and certain features and certain views of the figures may
be shown
exaggerated in scale or in schematic in the interest of clarity and
conciseness.
As used herein and throughout various portions (and headings) of this
patent application, the terms "invention", "present invention" and variations
thereof are
not intended to mean the invention of every possible embodiment of the
invention or any
particular claim or claims. Thus, the subject matter of each such reference
should not be
considered as necessary for, or part of, every embodiment of the invention or
any
particular claim(s) merely because of such reference. Also, it should be noted
that
reference herein and in the appended claims to components and/or aspects in a
singular
tense does not necessarily limit the present invention to only one such
component or
aspect, but should be interpreted generally to mean one or more, as may be
suitable and
desirable in each particular instance.
A method of allowing multiple fractures to be formed in a subterranean
formation for hydrocarbon recovery from an open hole completed well section in
accordance with the present invention will now be described with reference to
the well 10
of Figure 1. The illustrated well 10 includes a well bore 14 with a vertical
portion 16
having a casing 18 therein, and a non-vertical portion 22 that is open hole.
In this
example, the section 26 of the well 10, from which the subterranean formation
12 is to be
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CA 02655348 2009-02-24
fractured (the "fracture section") is in the non-vertical portion 22, which
extends to the
toe 24 of the well bore 14. As used herein, the term "fracture section" and
variations
thereof refers to the section or portion of the well or well bore from which
the formation
is intended to be fractured. As shown, the fracture section 26 of the
illustrated well 10
(see also Figure 6) is the horizontal, open hole portion. However, it should
be understood
that the present invention is not limited to the example of Figure 1.
In accordance with an embodiment of the present invention, a removable
coating 30 (e.g. Figure 2) is provided across the wall 36 of the well bore 14
at the fracture
section 26. As used herein the term "coating" and variations thereof means one
or more
at least substantially fluidly impermeable layer, skin, filter-cake, sheathe,
or the like
provided on the exposed surface of the subterranean formation that forms the
wall of the
well bore. The coating may have any suitable composition, thickness, coverage
across
the well bore wall and other properties, as long as it is (i) removable and
(ii) sufficient to
prevent failure or fracturing of the formation along the coated section of the
wall due to
fluid pressure that may be applied in the well to fracture the formation from
an adjacent
non-coated location in the well bore. Such a coating may sometimes be referred
to herein
as being "substantially impermeable" and provided across "substantially the
entire
surface" of the wall of the fracture section of the well bore. In some
instances, the
coating is substantially impermeable, strong and coherent, essentially
eliminates the
effects of linear poroelasticity on the formation under the coating regardless
of the nature
or type of hydrocarbons produced therefrom and in a wide range of
temperatures, may be
easily and quickly removed, may be 100% soluble or a combination thereof.
CA 02655348 2010-11-08
Referring to Figure 2, in the present embodiment, the coating 30 is
sufficiently thin so that it does not fill, block or substantially narrow the
well bore 14.
For example, the coating 30 may be thin enough not to block or hinder the
passage
through the well bore 14 of a coiled tubing, jointed pipe string and/or other
equipment
used in well completion. Such a coating 30 may sometimes be referred to herein
as a
"substantially thin" coating. In some applications of this embodiment, the
coating 30
may have a thickness of less than one millimeter (1 mm). However, in other
applications, the coating 30 may have a thickness greater than 1 mm.
As indicated above, the coating 30 may include any suitable components.
For example, the coating 30 may include particulate resin, cement, wax,
gilsonite, or
other acid or oil soluble materials. Various materials that may be suitable
for use as the
coating 30, depending upon the particular application, may be found in U.S.
Patent
Number 6,367,548 to Purvis et al., issued on April 9, 2002 and owned by the
present
assignee, as well as patents incorporated by reference therein, including U.S.
Patent No.
2,803,306 issued in August 1957 to Hower.
Still referring to Figure 2, one particular example coating 30 includes an
acid-soluble material that may be delivered in one or more fluid. Such a
mixture
including acid-soluble material and fluid is sometimes referred to herein as
the dispersion
40. In the present embodiment, a small quantity of fine or microfine acid-
soluble cement,
such as presently available MagneBlockTM cement base material commercially
sold by
the current assignee hereof, BJ Services Company, is mixed into water to form
a dilute
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cement-based dispersion 40. The particle size of the exemplary cement is small
enough
to remain suspended in the water so it does not completely harden or set-up in
the well
bore 14 during use, but is still capable of settling against the well bore
wall 36 to form the
coating 30 thereon. One or more suitable chemical additives may be included in
the
dispersion 40 to assist in keeping the cement particles suspended or for any
other desired
purpose.
The coating 30 may be delivered into the well bore 14 in any suitable
manner. In the present embodiment, referring back to Figure 1, a cement-based
dispersion 40 is delivered through a tubing 44 in the well bore 14 to form a
coating 30 at
the fracture section 26 thereof. Any suitable type of tubing 44 may be used,
such as a
jointed "frac" string or coiled-tubing 46. Likewise, the tubing 44 may have
any suitable
size, such as 2 7/8 inch diameter coiled tubing. In the example shown, the
front end 48 of
the coiled tubing 46 is initially positioned at the far end of the fracture
section 26
proximate to the toe 24 of the well bore 14. The dispersion 40 is pumped
through the
coiled tubing 36 into the well bore 14 in the vicinity of the toe 24 thereof
to preferably
completely fill the fracture section 26. Any water 32 (or other fluid) in the
fracture
section 26 will be pushed back by the dispersion 40 into a non-fracture
section of the well
bore 14 or out of the well 10.
Referring back to Figure 2, after the dispersion 40 has generally filled the
fracture section 26, the well 10 is shut-in at the surface 20. More dispersion
40 may be
pressure fed into the well bore 14, causing fluid in the dispersion 40 to leak
away (e.g.
arrows 52) into semi-permeable rock forming the wall 36 of the well bore 14.
As the
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CA 02655348 2009-02-24
cement particles in the dispersion 40 dehydrate, some of them may also leak
into the
rock, while others will bridge out and build-up against the wall 36 to form
the coating 30
thereon.
In some instances, it may be desirable or necessary to mildly increase the
fluid pressure in the fracture section 26 to build up a sufficient coating 30
around the
entire circumference of the wall 36 in the fracture section 26. In the present
embodiment,
as the pressure increases, leakage of the dispersion 40 into the subterranean
formation 12
will eventually decrease and the thickness of the coating 30 will increase.
The specific
pressure increase and pressurization duration may depend upon one or more
factors, such
as the composition of the coating 30 and/or subterranean formation 12, the
size of the
well 10, size of the tubing 44 and/or other variables.
In some applications, to ensure a substantially thin coating 30, it may be
necessary to reduce or stop the application of fluid pressure in the fracture
section 26. In
the present embodiment, after sufficient time has elapsed to allow the coating
30 to form
as desired, the remaining dispersion 40 may be displaced out of the fracture
section 26 of
the well 10 (e.g. Figure 3). For example, the valve(s) controlling the flow of
fluid
through the annulus 42 formed between the tubing 44 and well bore wall 36 may
be
opened and water 32 (or other desirable fluid) pumped through the coiled
tubing 46 to the
toe 24 of the well bore 14 to push the remaining dispersion 40 in the fracture
section 26
back into the vertical portion 16 of the well 10. In such instance, the
dispersion 40 will
principally reside in the casing 18, such as steel pipe, where it is generally
unable to
further leak-off or harden. The dispersion 40 will be available for future use
in the
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fracture section 26, if necessary, such as to reestablish the coating 30 at
certain locations.
Any fluid, such as water, in the well 10 above the dispersion 40 may be forced
up or out
of the well 10. The water 32 or other fluid pumped into the well bore 14 is
preferably
neutral so that it will not destabilize the coating 30 formed in the fracture
section 26.
However, the particular sequence and methodology for delivering the
coating 30 or dispersion 40 into the fracture section 26 may vary depending
upon one or
more factor, such as the existence of fluid or other material in the well
bore, type of
drilling fluid used, formation permeability, etc. For example, in some
instances, if the
well bore 14 initially contains any unneeded or undesirable fluid, such as
drilling mud or
completion fluid, such fluid may first be displaced out of the well 10 or the
fracture
section 26 before providing the coating 30 or dispersion 40. For example,
water may be
pumped through the tubing 46 into the well bore 14 to fill at least the
fracture section 26
and displace the undesirable fluid into another section of the well bore 14 or
entirely out
of the well 10.
For another example, it may necessary or desirable to remove existing
drilling fluid filter cake or other material (not shown) formed on the wall 36
of the
fracture section 26 before providing the coating 30. Such material may
interfere with the
formation or effectiveness of the coating 30, inhibit the ability of the
dispersion 40 to
adhere to the wall 36 or cause one or more other problems. As an example, the
tubing 44
may be positioned proximate to the toe 24 of the well bore 14. While pulling
the tubing
44 up through the fracture section 26, a fluid capable of washing off or
removing the
filter cake (or other material) from the wall 36 is pumped through the tubing
44 into the
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well bore 14. The pre-wash fluid may have any suitable composition (water,
additives,
solvents, other components) depending upon the well 10, type of drilling mud
utilized or
other factors. After such pre-washing, the dispersion 40 may be dispensed into
the well
bore 14 through the tubing 44 at or near the top of the fracture section 26,
such as at the
bottom of the casing 18, and thereafter as the tubing 44 is run back into the
well bore 14
toward the toe 24.
There may be other instances where it is desirable or necessary to circulate
the dispersion 40 in the well bore 14 at the near end of the fracture section
26 or
proximate to the casing 18, and thereafter as the tubing 44 is run into the
well to the toe
24. For example, this technique may be useful when it is difficult to pre-
position the
tubing 44 at the toe 24 of the well, such as when the tubing 44 becomes
differentially
stuck in the well bore 14 at some intermediate location. In some embodiment,
the
dispersion 40 or other coating 30 may instead be pumped or otherwise delivered
to the
fracture section 26 of the well 10 from the surface 20 through the annulus 42
and the well
bore fluids returned up through the tubing 44.
Referring now to Figure 3, in the present embodiment, the coating 30 is
selectively removed from the fracture section 26 at a desired location of
initiation 54 of a
first fracture sufficient to allow a first fracture to be formed in the
subterranean formation
12. Any suitable technique and/or coating remover may be used to remove the
coating 30
at the first fracture initiation location 54. For example, the coating remover
may be a
mechanical device (not shown) for selectively removing the coating 30. In
other
CA 02655348 2009-02-24
examples, a fluid-delivered coating remover may be provided into the well bore
14
through the tubing 44 or the annulus 42 to the first fracture initiation
location 54.
In the illustrated embodiment, the desired location of initiation 54 of the
first fracture is proximate to the toe 24 of the well bore 14. After the
necessary volume
of water 32 or other neutral fluid is pumped into the illustrated well bore 14
to displace
the remaining dispersion 40 out of the fracture section 26, a cement-
dissolving acid 58
(or other suitable substance) is provided through the coiled tubing 46 to the
first fracture
initiation location 54. For example, the water 32 or other neutral fluid may
be followed
by a lead slug of acid 58 and the pad of the planned fracture treatment.
The acid 58 (or other suitable substance) is provided to dissolve the
exemplary coating 30 from the well bore wall 36 at that location, but without
at least
substantially dissolving the coating 30 at any other location in the well bore
14 or the
fracture section 26 thereof. In the present embodiment, a minimal quantity of
acid 58
capable of dissolving the coating 30 at (only) the first fracture initiation
location 54 in a
reasonable time period may be provided. The quantity of acid 58 (or other
substance)
and the time allowed to remove the coating 30 may depend upon one or more
variable,
such as the composition of the coating 30 and type of acid 58, thickness of
the coating 30
and/or one or more well properties. In some applications, the time allowed for
acidizing
the first fracture initiation location 54 may be approximately ten minutes,
while in other
applications, it may be more or less than ten minutes.
For example, if the tubing 44 has an internal volume of thirty barrels of
fluid, after twenty-nine barrels of neutral fluid 32 are pumped through the
tubing 44 into
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the fracture section 26, the annulus 42 is shut-in and a single barrel of acid
58 is squeezed
out the end 48 of the tubing 44. As the acid 58 is displaced into the closed
annulus 42,
the acid 58 will remain locally near the end 48 of the tubing 44 and not
migrate through
the fracture section 26. In some instances, it may be desirable to apply a
slight positive
pressure in the annulus 42 from the surface as the acid 58 is displaced out of
the tubing
44 to assist in inhibiting the uncontrolled movement of the acid 58 in the
well bore 14
and focusing the acid 58 to react through the coating 30 at the desired
location.
It should be noted that the acid 58 (or other suitable substance) may have
one or more additional benefit. For example, as the acid 58 dissolves the
coating 30 at
the desired fracture initiation location, the acid 58 may also react with the
formation 12.
If the dispersion 40 leaked into the formation 12 or another filter cake was
formed inside
the formation 12, the acid 58 may dissolve it and assist in weakening the rock
in advance
of the fracturing treatment and promoting formation breakdown.
After the illustrated coating 30 is sufficiently removed at the desired first
fraction initiation location 54, a first fracture is allowed to be formed at
that location.
Any suitable fracturing technique may be used. In the embodiment of Figure 4,
hydraulic
fracturing, as is or becomes know, is used to form the fractures by pumping
hydraulic
fracturing fluid 68 through the tubing 44 into the well bore 14 proximate to
the first
fracture initiation location 54. In other embodiments, hydraulic fracturing
fluid 68 may
instead be delivered to the first fracture initiation location 54 through the
annulus 42. In
yet other embodiments hydraulic fracturing fluid 68 may be provided to the
first fracture
initiation location 54 through both the tubing 44 and the annulus 42. For
example,
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hydraulic fracturing fluid including proppant may be delivered to the first
fracture
initiation location 54 through the tubing 44 and hydraulic fracturing fluid
not including
proppant may be provided through the annulus 42, such as to avoid removal of
the
coating 30 in the fracture section 26 other than at the first fracture
initiation location 54.
The adjacent coated subterranean formation forming the bore hole wall 36
in the remainder of the fracture section 26 of the well bore 14 should be
stronger than the
non-coated portion (at the first fracture initiation location 54) and unlikely
to fail under
the hydraulic pressure needed to fracture the non-coated portion, allowing
precise
location of the initiation of the first fracture. For example, the non-coated
portion of the
formation 12 (forming the bore hole wall 36 at the first fracture location 54)
should be
subject to the effects of linear poroelastic stress, while the adjacent coated
formation 12
should remain substantially isolated therefrom. Under the theory of linear
poroelasticity,
which describes the mechanical effect of adding or removing fluid from rock
pores, an
increase in fluid pressure on a porous rock induces dilation (e.g. cracking)
of the rock.
Because of the suitably impermeable, strong and coherent nature of the coating
30, the
effect of linear poroelasticity on the coated parts of the fracture section 26
are preferably
reduced or eliminated, isolating those coated areas from cracking or fracture
caused by
the applied pressure, possibly intensifying stress placed on the non-coated
area.
However, the present invention is not limited to reducing or eliminating
linear poroelastic
stress on the coated parts of the bore hole wall 36.
Still referring to the embodiment of Figure 4, the rock pores at the first
fracture initiation location 54 should preferentially fail and crack. When the
formation 12
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cracks, the well pressure should typically drop at the breakdown pressure of
the rock. If
desired or necessary, as fracture fluid 68 leaks off into the crack, fluid
pressure may be
increased to cause the crack to open and propagate, forming the first fracture
62. The
magnitude of applied fluid pressure in the fracture section 26 of the well
bore 14 and
duration of pressurization sufficient to crack the formation 12 at the first
fracture
initiation location 54 and not crack the formation throughout the remainder of
the fracture
section 26 of the well bore 14 may, in any particular instance, depend upon
one or more
variables, such as one or more formation properties, well bore size, tubing
size, etc.
In the present embodiment, as the first fracture 62 is formed, a proppant or
other material or mixture is provided to prop the fracture 62 open, as is or
becomes
known. As the fracture 62 fills with the proppant (or other suitable material
or mixture),
a removable plug 72 (e.g. Figure 5) of the same proppant or a different
proppant, sand, or
other suitable material or mixture, is provided in the well bore 14 around the
first fracture
initiation location 54 and proximate thereto to shield it from fracturing
during the
subsequent fracturing operations and/or avoid damage to the first fracture 62.
Any
suitable removable plugging materials may be used for the plug 72, such as
proppant,
lightweight proppant or sand, etc. In the present embodiment, the plug 72
includes
plugging material that does not invade the propped fracture 62 or impair
fracture
conductivity, and is easy to clean out. For example, as the fracture 62 fills
with proppant,
the pump rate of the proppant may be decreased and the tubing 44 pulled up the
well 10,
leaving a plug 72 of proppant in the well bore 14 to cover the treated zone.
19
CA 02655348 2009-02-24
After the first fracture is formed, additional fractures may be formed at
different locations in the fracture section 26 of the well bore 14, if
desired. For example,
as shown in Figure 6, a second fracture 82 may be formed at a second fracture
initiation
location 78 after the coating 30 is removed therefrom, followed by a third
fracture 88 at a
third fracture initiation location 84, a fourth fracture 90 at a fourth
fracture initiation
location 86, a fifth fracture 92 at a fifth fracture initiation location 94
and so on.
In the present embodiment, referring back to Figure 5, the end 48 of the
tubing 44 is moved to a second fracture initiation location 78 up-hole from
the first
fracture 62, and the previously described process is repeated. For example,
the coating
30 may be selectively removed from the second fracture initiation location 78
sufficient
to allow a fracture to be formed in the subterranean formation 12. If desired,
a cement-
dissolving acid 58 (or other suitable substance) may be provided through the
tubing 44,
such as described above, to dissolve the coating 30 from the well bore wall 36
at the
second fracture initiation location 78, but without at least substantially
dissolving the
coating 30 at any other location in the well bore 14.
Still in accordance with the present embodiment, referring to Figure 7,
after the coating 30 is removed from the second fracture initiation location
78, the second
fracture 82 may be formed in the formation 12 at the second fracture
initiation location
78. For example, hydraulic fracturing fluid 68 may be pumped through the
tubing 44 into
the well bore 14 proximate to the second fracture initiation location 78
sufficient to crack
and fracture the formation 12 at that location without fracturing the
formation at any
coated location of the well bore 14, such as described above with respect to
the first
CA 02655348 2009-02-24
fracture initiation location 54. The plug 72 provided in the well bore 14 at
the first
fracture initiation location 54 isolates that area from being affected by any
increase in
applied fluid pressure in the well bore 14 during fracturing/treatment of the
second
fracture 82.
After the second fracture 82 is initiated or formed, the plug 72 in the well
bore 14 at the first fracture 62 and/or the coating 30 between the first and
second
fractures 62, 82 may be partially or fully removed, if desired. Any suitable
technique
may be used, as long as the coating 30 on the well bore wall 36 up-hole of the
second
fracture initiation location 78 is not removed if additional up-hole
fracturing is desired.
However, the plug 72 and coating 30 may instead be removed after all the
desired
fractures are formed. Also if desired, a plug 72 (e.g. Figure 6) may then be
provided in
the well bore 14 around the second fracture 82, such as described above with
respect to
the first fracture 62.
In this embodiment, the same process may be repeated multiple times to
create as many distinct fractures in the formation 12 from the fracture
section 26 of the
well bore 14 as is practical, reasonable and/or desired. In the embodiment of
Figure 6, a
total of ten successively placed exemplary fractures are shown, each fracture
formed at a
higher portion of the fracture section 26 of the well bore 14 from the
previously placed
fracture. In one example, each fracture formed in a fracture section 26 having
a rough
estimated length of 10,000 feet may be located in the range of 100-1,000 feet
up-hole of
the previously formed fracture.
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CA 02655348 2009-02-24
If desired, after all the desired fractures are formed, any remaining coating
30 and plugs 72 in the well bore 14 may be removed using any suitable
technique. For
example, a suitable pressurized acid mixture (not shown) may be pumped through
the
tubing 44 while moving the tubing forward in the well bore 14 toward the toe
24 from the
last formed fracture initiation location, removing the remaining coating 30
from the well
bore wall 36 and pushing it, along with material forming any plugs 72, up
through the
annulus 42 and out of the well 10. Thereafter, the well 10 may be produced as
desired.
The methods described above and claimed herein and any other methods
which may fall within the scope of the appended claims can be performed in any
desired
suitable order and are not necessarily limited to the sequence described
herein or as may
be listed in the appended claims. Further, the methods of the present
invention do not
necessarily require use of the particular embodiments shown and described in
the present
application, but are equally applicable with any other suitable structure,
form and
configuration of components.
While preferred embodiments of the invention have been shown and
described, many variations, modifications and/or changes of the methods and
system of
the present invention, such as in the components, details of construction and
operation,
arrangement of parts and/or methods of use, are possible, contemplated by the
patent
applicant(s), within the scope of the appended claims, and may be made and
used by one
of ordinary skill in the art without departing from the spirit or teachings of
the invention
and scope of appended claims. Thus, all matter herein set forth or shown in
the
accompanying drawings should be interpreted as illustrative, and the scope of
the
22
CA 02655348 2009-02-24
invention and the appended claims should not be limited to the embodiments
described
and shown herein.
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